Heavy Oil Recovery and Apparatus

ABSTRACT

A thermal in-situ method and apparatus are provided for recovering hydrocarbons from subterranean hydrocarbon-containing formations such as oil sands, oil shale and other heavy oil systems. Recovery of viscous hydrocarbon by hot fluid injection into subterranean formations is assisted by using a specially designed wellbore with an active hydraulic seal, with a axial communication zone with multiple injection perforations separated from the production perforations by a moveable packer. In addition, a novel downhole thermal sensing apparatus is used to monitor and control oil production. A producing mechanism including pumping equipment lifts the produced oil from the central cavity to the surface.

CROSS REFERENCES

Reference is made to DD 596,606 filed Mar. 16, 2006 by the inventor.

INTRODUCTION

This invention relates generally to a new technology application used inrecovery of heavy and viscous hydrocarbons from subterranean oil bearingformations during hot fluid injection. The technology described is theSingle Well Acceleration Production process, herein abbreviated as SWAPwhich allows a single wellbore to perform simultaneously, injection andproduction operations in heavy oil recovery systems.

This invention is related to prior filings by the same applicant,pertaining to the overall recovery of hydrocarbons from subterranean oilformations. The technology involves the novel use and application ofequipment and techniques in which steam or other hot fluids are injectedinto substantially horizontal wellbores in which injection andproduction is obtained from the same wellbore.

One of the new types of horizontal well is called a Uniwell™ because itcan have at least two surface wellheads one at each end of the axis ofthe horizontal system. Either wellhead can be used for either injectionor production as needed by the operator.

The technology has been the subject of several prior applications by thesame inventor. This particular invention relates to use of a specializedannular fluid communication zone between the steam zone and theproduction zone and the additional use of a downhole apparatus toselectively monitor flowing fluid characteristics and subsequentlycontrol hot oil production in order to facilitate the injection of steaminto the steam bank zone. This control mechanism effects oildisplacement by maintaining a viable hydraulic seal in the communicationzone between the steam displacement zone and the production zone of thewellbore.

This novel completion technique uses injection and productionperforations separated by a moveable wellbore packer and this newapparatus is implemented between the injection and productionperforations in the wellbore to sense and monitor the flow of steam andcontrol the production of hot oil.

FIELD OF INVENTION

THIS INVENTION is a unique new approach to heavy oil recovery combininghorizontal and lateral wells, steam injection and specialized downholedevices to facilitate operations and to significantly accelerate oilproduction.

The invention is particularly suited to making heavy oil formations, oilshales and tar sands producible by a single wellbore drilled using aspecialized form of horizontal directional drilling. The inventionhowever is not limited to recovery of heavy oils only; it can be usedfor many oil recovery processes such as tar sands and oil shales.

BACKGROUND OF THE INVENTION

1. Introduction

Heavy hydrocarbons in the form of petroleum deposits are distributedworldwide and the heavy oil reserves are measured in the hundreds ofbillions of recoverable barrels. Because of the relatively highviscosity, up to a million cp, these crude deposits are essentiallyimmobile and cannot be easily recovered by conventional primary andsecondary means. The only economically viable means of oil recovery isby the addition of heat to the oil deposit, which significantlydecreases the viscosity of the oil and allows the oil to flow from theformation into the producing wellbore. Today, the steam injection can bedone in a continuous fashion or intermittently as in the so-called “huffand puff” or cyclic steam process. Oil recovery by steam injectioninvolves a combination of physical processes including, steamdistillation, gravity drainage, steam drive and steam drag to move theheated oil from the oil zone into the producing wellbore.

Horizontal wells and lateral wells have played a prominent part inrecovery of oil. These wells can be as much as 4 times as expensive todrill as conventional vertical wells but the increased expenses areoffset by the increases in rates of oil production and faster economicreturns. Several patents have described various approaches to usinghorizontal wellbores. The need for horizontal wells requires a moreefficient economical and easily deployable system for developing,drilling and utilizing these horizontal wells. The need to accelerateoil production without waiting for steam to traverse several hundredfeet of reservoir rock between injection and production wells hascreated this new technology. In this technology an approach is usedwherein oil production occurs almost simultaneously with steam injectioninitiation.

2. Prior Art

Various methods and processes have been disclosed for recovery of oiland gas by using horizontal wells. There have been various approachesutilized with vertical wellbores, to heat the reservoirs by injection offluids and also to create a combustion front in the reservoir todisplace the insitu oil from the injection wellbore to the productionwellbore.

U.S. Pat. No. 3,986,557 claims a method using a horizontal well with twowellheads that can inject steam into a tar sand formation mobilizing thetar in the sands. In this patent, during the injection of the steam itis hoped that the steam will enter the formation and not continuedirectly down the open wellbore and back to the surface of the oppositewellhead. It is technically difficult to visualize the steam entering acold formation with extremely highly viscous oil, while a completelyopen wellbore is readily available for fluid flow away from theformation. Furthermore, U.S. Pat. No. 3,986,557 teaches that the steamis simultaneously injected through perforations into the cold bitumenformation while hot oil is flowing in the opposite direction against theinvading high pressure steam through the same perforations through therock pore structure. This situation is not only physically impossiblebut it thermodynamically impossible for the steam fluid to flow out of,and hot oil flow back into the same perforations simultaneously.

U.S. Pat. No. 3,994,341 teaches a vertical closed loop system inside thewellbore tubulars in which a vertical wellbore is used to generate avertical circulation of hot fluids which heat the wellbore and nearbyformation. Hot fluids and drive fluids are injected into upperperforations which allow the driven oil to be produced from the bottomof the formation after being driven towards the bottom by the drivefluid.

U.S. Pat. No. 4,034,812 describes a cyclic injection process where asingle wellbore is drilled into an unconsolidated mineral formation andsteam is injected into the formation for a period of time to heat theviscous petroleum near the well. This causes the unconsolidated mineralsand grains to settle to the bottom of the heated zone in a cavity andthe oil to move to the top of the zone.

U.S. Pat. No. 4,037,658 teaches the use of two vertical wells connectedby a cased horizontal shaft or “hole” with a flange in the verticalwell. This type of downhole flange connection is extremely difficult ifnot impossible to implement in current oilfield practice. Two types offluids are used in this patent, one inside the horizontal shaft as aheater fluid and one in the formation as a drive fluid. Both fluids areinjected either intermittently or simultaneously from the surfacewellheads.

Butler et al in U.S. Pat. No. 4,116,275 use a single horizontal wellborewith multiple tubular strings internal to the largest wellbore for steamrecovery of oil. Steam was injected via the annulus and after a soakperiod, the oil is produced from the inner tubing strings. This approachis basically a modified “Huff & Puff” displacement in which theinjection “huff” is done through a complex pre-heated horizontal wellbore and the well put on production, the “puff” cycle after a soakperiod of several days. In other patents, U.S. Pat. Nos. 4,085,803,4,344,485, 5,407,009, 5,607,016, Butler describes further uses ofhorizontal wells, solvent type and steam displacement mechanisms toproduce viscous oils from tar sands using his SAGD technology.

U.S. Pat. No. 4,445,574 teaches the drilling of a single well with twowellheads. This well is perforated in the horizontal section and aworking fluid is injected into the wellbore to produce a mixture ofreservoir oil and injected working fluid. Similar to the U.S. Pat. No.3,986,557 patent it is difficult from a hydraulic point of view tovisualize and contemplate the working fluid entering the formation in avertical direction while an open wellbore is available for fluid flowhorizontally and vertically out the distal end of this wellbore.

U.S. Pat. No. 4,532,986 teaches an extremely complex dual well systemincluding a horizontal wellbore and a connecting vertical wellbore whichis drilled to intersect the horizontal well. The vertical well containsa massively complex moveable diverter system with cables and pulleysattached to the two separate wellheads to allow the injection of steam.This system is used to inject steam from the vertical wellhead into thehorizontal wellbore cyclically and sequentially while the oil isproduced from the wellhead at the surface end of the horizontal well.

Huang in U.S. Pat. No. 4,700,779 describes a plurality of parallelhorizontal wells used in steam recovery in which steam is injected intothe odd numbered wells and oil is produced in the even numbered wells.Fluid displacement in the reservoir occurs in a planar fashion.

U.S. Pat. No. 5,167,280 teaches single concentric horizontal wellboresin the hydrocarbon formation into which a diffusible solvent is injectedfrom the distal end to effect production of lowered viscosity oilbackwards at the distal end of the concentric wellbore annulus.

U.S. Pat. No. 5,215,149 Lu, uses a single wellbore with concentricinjection and production tubular strings in which the injection isperformed through the annulus and production occurs in the inner tubularstring, which is separated by a packer. This packer limits the movementof the injected fluids laterally along the axis of the wellbores. Inthis invention, the perforations are made only on the top portion of theannular region of the horizontal well. Similarly, the production zonebeyond the packer is made on the upper surface only of the annularregion. These perforated zones are fixed at the time of well completionand remain the same throughout the life of the oil recovery process.

Balton in U.S. Pat. No. 5,402,851 teaches a method wherein multiplehorizontal wells are drilled to intersect or terminate in closeproximity a vertical well bore. The vertical wellbore is used toactually produce the reservoir fluids. The horizontal wellbore providesthe conduits, which direct the fluids to the vertical producingwellbore.

U.S. Pat. No. 5,626,193 by Nzekwu et al disclose a single horizontalwell with multiple tubing elements inside the major wellbore. Thishorizontal well is used to provide gravity drainage in a steam assistedheavy oil recovery process. This invention allows a central injectortube to inject steam and then the heated produced fluids are producedbackwards through the annular region of the same wellbore beginning atthe farthest or distal end of the horizontal wellbore. The oil is thenlifted by a pump. This invention shows a process where the input andoutput elements are the same single wellbore at the surface.

U.S. Pat. No. 5,655,605 attempts to use two wellbores sequentiallydrilled from the surface some distance apart and then to have thesehorizontal wellbore segments intersect each other to form a continuouswellbore with two surface wellheads. This technology while theoreticallypossible is operationally difficult to hit such a small undergroundtarget, i.e the axial cross-section of a typical 8-inch wellbore using ahorizontal penetrating drill bit. It further teaches the use of thehorizontal section of these intersecting wellbores to collect oilproduced from the formation through which the horizontal sectionpenetrates. Oil production from the native formation is driven by aninduced pressure drop in the collection zone by a set of valves or apumping system which is designed into the internal concentric tubing ofthis invention. The U.S. Pat. No. 5,655,605 patent also describes aheating mechanism to lower the viscosity of the produced oil inside thecollection horizontal section by circulating steam or other fluidthrough an additional central tubing located inside the horizontalsection. At no time does the steam or other hot fluid actually contactthe oil formation where viscosity lowering by sensible and latent heattransfer is needed to allow oil production to occur.

U.S. Pat. No. 6,708,764 provides a description of an undulating wellbore. The undulating well bore includes at least one inclining portiondrilled through the subterranean zone at an inclination sloping towardan upper boundary of the single layer of subterranean deposits. At leastone declining portion is drilled through the subterranean zone at adeclination sloping toward a lower boundary of the single layer ofsubterranean deposits. This embodiment looks like a waveform situated inthe rock formation.

U.S. Pat. No. 6,725,922 utilizes a plurality of horizontal wells todrain a formation in which a second set of horizontal wells are drilledfrom and connected to the first group of horizontal wells. These wellsfrom a dendritic pattern arrangements to drain the oil formation.

U.S. Pat. No. 6,729,394 proposes a method of producing from asubterranean formation through a network of separate wellbores locatedwithin the formation in which one or more of these wells is a horizontalwellbore, however not intersecting the other well but in fluid contactthrough the reservoir formation with the other well or wells.

U.S. Pat. No. 6,948,563 illustrates that increases in permeability mayresult from a reduction of mass of the heated portion due tovaporization of water, removal of hydrocarbons, and/or creation offractures. In this manner, fluids may more easily flow through theheated portion.

U.S. Pat. Nos. 6,951,247, 6,929,067, 6,923,257, 6,918,443, 6,932,155,6,929,067, 6,902,004, 6,880,633, 20050051327, 20040211569 by variousinventors and assigned to Shell Oil Company have provided a veryexhaustive analysis of the oil shale recovery process using a pluralityof downhole heaters in various configurations. These patents utilize amassive heat source to process and pyrolize the oil shale insitu andthen to produce the oil shale products by a myriad of wellboreconfigurations. These patents teach a variety of combustors withdifferent geometric shapes one of which is a horizontal combustor systemwhich has two entry points on the surface of the ground, however thehydrocarbon production mechanism is considerably different from thoseproposed herein by this subject invention.

U.S. Pat. No. 6,953,087 by Shell, shows that heating of the hydrocarbonformation increases rock permeability and porosity. This heating alsodecreases water saturation by vaporizing the interstitial water. Thecombination of these changes increases the fluid transmissibility of theformation rock in the heated region.

U.S. Pat. No. 5,896,928 teaches a “dumb” downhole fluid flow controldevice that is electrically operated from either the surface ordownhole. This device is a simple on-off device, which restricts flow,but is unable to determine, process and operate based on the sensiblecharacteristics of the flowing fluid such as the current inventiondiscussed herein.

A further U.S. Pat. No. 5,868,201 illustrates a downhole system thatsenses pressure and that actuate a valve system for control of the fluidflow remotely. Similar to U.S. Pat. No. 5,896,928 this system is unableto operate based on the sensible characteristics of the flowing fluid asis needed in the case of steam, flow where pressure is a minor parameterin determining flow regimes.

U.S. Pat. No. 6,006,832 discusses a formation sensor system formonitoring a producing formation in-situ by using permanently mountedsensors in the wellbore. These sensors monitor formation propertiesusing gamma ray, neutron and resistivity sensors. These type sensors arepassive and measure rock and interstitial fluid properties needed todiscriminate rock types and properties. On the other hand, the presentinvention herein senses flow parameters and properties needed for flowcontrol.

Patent application 20050072578 describes a thermally controlled valve.This thermally controlled valve is a device that is capable ofregulating the flow of material into, through, and out of a wellbore inresponse only to a change in temperature near the valve. All of thesubsequent systems related to the valve operation depend on thetemperature behavior and its measurement. In steam operations wherethere is a need to regulate steam flow in porous media such as injectionand production in subterranean heavy oil formations, there is anindispensable requirement to determine the total characteristics of theflowing material. A simple temperature record is insufficient todetermine whether flow is a gas, a liquid or a solid. To fully describewhat fluid is flowing one needs the temperature, pressure and quality inthe case of steam. The 20050072578 application does not address thisfact and as such is incapable of discriminating between hot oil, hotwater and steam in the flow stream and will be inadequate as acontroller of steam flow and a reliable steam shut off mechanism as isneeded in heavy oil field steam displacement processes.

The Society of Petroleum Engineers Reference 1, SPE paper 20017 teachesa computer simulation of a displacement process using a concentricwellbore system of three wellbore elements and complex packers in whichsteam is injected in a vertical wellbore similar to that in the U.S.Pat. No. 3,994,341 patent. Simulated steam injection occurs through onetubing string and circulates in the wellbore from just above the bottompacker to the injection perforations near the top of the tar sand. Thisperforations near the top of the tar sand. This circulating steam turnsthe wellbore into a hot pipe which heats an annulus of tar sand andprovides communication between the steam injection perforations near thetop of the tar sand and the fluid production perforations near thebottom of the tar sand. This process requires an injection period of 7years to increase oil production from 20 BOPD to 70 BOPD.

Paper 37115 describes a single-well technology applied in the oilindustry which uses a dual stream well with tubing and annulus: steam isinjected into the tubing and fluid is produced from the annulus. Thetubing is insulated to reduce heat losses to the annulus. Thistechnology tries to increase the quality of steam discharged to theannulus, while avoiding high temperatures and liquid flashing at theheel of the wellbore.

SPE paper 50429 presents an experimental horizontal well where thehorizontal well technology was used to replace ten vertical injectionwells with a single horizontal well with limited entry. Thelimited-entry perforations enabled steam to be targeted at the coldregions of the reservoir.

SPE paper 37089 presents an experimental SAGD study in which the lowerhorizontal well functions as an intermittent steam-injector and acontinuous oil-producer, instead of the usual SAGD production-well whilesteam is also injected continuously through the upper well.

SPE paper 50941 presents the “Vapex” process which involves injection ofvaporized hydrocarbon solvents into heavy oil and bitumen reservoirs;the solvent-diluted oil drains by gravity to a separate and differenthorizontal production well or another vertical well. SPE paper 53687shows the production results during the first year of a thermalstimulation using dual and parallel horizontal wells using the SAGDtechnology in Venezuela.

SPE paper 75137 describes a THAI—‘Toe-to-Heel Air Injection’ systeminvolving a short-distance displacement process, that tries to achievehigh recovery efficiency by virtue of its stable operation and abilityto produce mobilized oil directly into an active section of thehorizontal producer well, just ahead of the combustion front. Air isinjected via a separate vertical or a separate horizontal wellbore intothe formation at the toe end of different horizontal producer well andthe combustion front moves along the axis of the producer well.

SPE 14916 describes the problem of the dual horizontal wells in aformation with a horizontal shale barrier. This barrier slows down therecovery under the SAGD system of dual horizontal wells since the steambank formation is slowed by the shale. This analysis also confirms thatthe gaseous steam overrides the cold viscous crude zone as it isinjected into the reservoir. SPE paper 78131 published an engineeringanalysis of thermal simulation of wellbore in oil fields in westernCanada and California, U.S.A.

SPE paper 92685 describes U-tube well technology in which two separatewellbores are drilled and then connected to form a single wellbore. TheU-tube system was demonstrated as a means of circumventing hostilesurface conditions by drilling under these physical obstacles.

SPE 54618 and SPE 37115 describe and illustrate a series of heavy oilproduction mechanisms. They describe a “technically challenging” processwhereby in single well gravity drainage process steam is injected intothe “toe” or distal end of a horizontal well while oil is produced atthe “heel” or proximal end. This system is similar to other approachesin the prior art and has a serious drawback in that neither investigatordescribes how the backwards flow from the “toe” to the “heel” can occurunder reservoir conditions with the extremely viscous in-situ oil. Thereis no viable mechanism for the hot oil to travel to the producing pointat the heel. However, in this subject application, this conceivablyinsurmountable obstacle is overcome by implementing a communication zonewhich forms an active channel between the growing steam bank and thedownstream production zone.

Reference 2 shows conclusively that the gravity drainage effect is themost critical factor in oil recovery in heavy oil systems undergoingdisplacement by steam.

Very few of these prior art systems, except the SAGD and Huff & Puffprocesses, have been used in the industry with any success because oftheir technical complexity, operational difficulties, and beingphysically impossible to implement or being extremely uneconomicalsystems.

For example, in U.S. Pat. No. 3,994,341, this patent which although onthe surface it has several similar aspects of the invention herein,differs significantly since, the U.S. Pat. No. 3,994,341 patent forms avertical passage way only by circulating a hot fluid in the wellboretubulars to heat the nearby formation, the U.S. Pat. No. 3,994,341patent claims the drive fluid promotes the flow of the oil by verticaldisplacement downwards to the producing perforations at the bottom, theU.S. Pat. No. 3,994,341 patent teaches the production perforations areset at the bottom of the vertical formation, a distance which can beseveral hundred feet. In this U.S. Pat. No. 3,994,341 embodiment, sinceno control mechanism like a back pressure system or pressure controlsystem is taught, it is obvious that the high pressure drive steam,usually at several hundred psi, will preferentially flow down thevertical passageway immediately on injection and bypass the coldformation with its highly viscous crude and extremely lowtransmissibility. Secondly, the large distance between the top of theformation and the bottom of the formation will cause condensation of thedrive steam allowing essentially hot water to be produced at the bottomwith low quality steam, both fluids being re-circulated back to thesurface. In addition, the mechanism to heat the near wellbore can onlybe based on conductive heat transfer through the steel casing. There isineffective heat transfer since there is no direct steam contact withthe formation rock in which latent heat transfer to formation fluids androck can occur, this latent heat being the major heat transport system.The U.S. Pat. No. 3,994,341 process is incapable of deliveringsufficient heat in a reasonable time to heat the formation sufficientlyto lower the viscosity of the oil, raise the porosity and permeabilityof the formation as taught in the present patent application.

Additionally many of the downhole devices patented to control fluid flowin the downhole wellbores are designed as “dumb” systems. Theseso-called dumb systems simply open or close a flow device depending onan event such as a pressure level or a temperature level. None of thedevices used in the heavy oil recovery system by steam to date, examinethe quality of the flowing fluid in the novel communication zone todiscriminate its nature and thus restrict flow based on this knowledgeto maintain a hydraulic seal.

In steam operations where there is a need to regulate steam flow inporous media such as injection and production in subterranean heavy oilformations, there is an indispensable requirement to determine the totalcharacteristics of the flowing material. A simple temperature record isinsufficient to determine whether flow is a gas, a liquid or a solid. Tofully describe what fluid is flowing one needs the temperature, pressureand quality in the case of steam. The prior art applications do notadequately address this fact and as such are incapable of discriminatingbetween hot oil, hot water and steam in the flow stream and will beinadequate as controllers of steam flow and thereby reliable steam shutoff mechanisms as are needed in heavy oil field steam recoveryoperations.

The most significant oil recovery problem with heavy oil, tar sands andsimilar hydrocarbonaceous material is the extremely high viscosity ofthe native hydrocarbons. The viscosity ranges from 10,000 cp at the lowend of the range to 5,000,000 cp at reservoir conditions. The viscosityof steam at injection conditions is about 0.020 cp. Assuming similarrock permeability to both phases steam and oil, then the viscosity ratioprovides a good measure of the flow transmissibility of the formation toeach phase. Under the same pressure, gradient, gaseous steam cantherefore flow from 500,000 to 250,000,000 times easier through thematerial than the oil at reservoir conditions. Because of this viscosityratio, it is imperative and critical to any recovery application thatthe steam be confined or limited to a continuous 3-dimensionalvolumetric zone in the reservoir by a seal. This seal can be physical,hydraulic or pneumatic and essentially must provide a physical situationwhich guarantees no-flow of any fluid across an interface. This can beimplemented by several means. Without this “barrier” the steam willbypass, overrun, circumvent, detour around the cold viscous formationand move to the producer wellbore. This invention addresses and resolvesthis major obstructive element in heavy oil recovery by implementing ahydraulic seal at the bottom of the steam bank and in the communicationzone.

There is a long felt need in the industry for a means of moving theheated low viscosity crude oil that has been contacted by the steam inthe steam zone to a place or location where it can be produced withouthaving to move it through a cold heavily viscous oil impregnatedformation. This problem has continued to baffle the contemporary andprior art with possibly the only exception being the SAGD patent whichuses two horizontal wellbores closely juxtaposed in a vertical plane.Even this SAGD approach has inherent difficulties in initiating the hotoil flow between the two wellbores. Trying to push the hot oil through acold formation is an intractable proposition.

In a much-reported SAGD process that has been used extensively inCanada, there are other shortcomings that limit the efficacy of theprocess and which have been overcome in this subject invention. It iswell known that the SAGD production well must be throttled to maintainthe production temperature below the saturation steam temperature toallow a column of fluid to exist over 100% of the production well tominimize bypass of steam. In some situations, in this very operation thenewly injected steam comes into the formation at the lower end of thesteam bank. It then passes vertically through the overlying hot oil andhot water re-heating this mixture repeatedly which must be kept cool toprevent bypassing of steam; this is called the “sub-cool” effect. Inessence, this thermodynamically inefficient process is analogous torunning an air conditioner and a heater simultaneously to maintain aroom at a fixed temperature. Further, even though the SAGD tries toutilize a limited hydraulic seal as is described in this subjectinvention, the implementation in this subject patent application is moreprecise, more operationally efficient and does not provide anydetrimental effects on the overall steam process. Having to inject thesteam through existing hot oil and water uses up part of the latent heatof the steam which is critical to good reservoir heating and effectiveoil displacement. This heat loss lowers the overall recovery of theprocess. In the subject process there is no operational loss of latentheat since the hot oil-water leg is at the bottom of the steam bank andthe communication zone and steam is injected directly into the nativeformation above and not through the oil-water accumulation zone with noloss of heat energy.

There are flow control issues that are inherent in the SAGD process thatare not present in the SWAP process invented herein. In the SAGD processthe operator has to critically control the steam flow rate along thecomplete length of the SAGD injection wellbore. This wellbore can beseveral thousand feet in length as it is drilled substantiallyhorizontally, however any deviation from the horizontal of the producingwellbore provides a potential zone where the steam can break throughfrom the higher injector and “short circuit” the recovery process byproducing steam in the lower producer. Maintaining precise horizontalseparation as well as the same azimuth, between two lateral wellboresover several hundred feet and more than a thousand feet, is not easy andas such the SAGD process puts higher initial capital costs and difficultand stringent long term operational demands on the recovery process. Onthe other hand the SWAP process presented herein only needs to controlthe vertical flow in an axial communication zone over a distance of afew feet. This control is easily performed by the hydraulic seal whichfills the communication zone and extends upwards into the bottom zone ofthe steam bank in much the same way as a heavy fluid can rest at thebottom of a kitchen sink over a plugged sink drain while a lighter fluidremains above. Because of the large volumetric extent of the steam bankencompassing several thousand barrels, production of the accumulatedfluids at the bottom of the steam bank can occur for a substantial timebefore the level of the hydraulic seal is lowered by a few feet. Forexample, lowering a one acre steam bank one foot can deliver about 1,200barrels of hot oil and water into the wellbore. This slow lowering offluid levels allows efficient control of the production process andlimits the potential of steam break through into the productionwellbore.

A further aspect of the SAGD process is pointed out by in SPE 97647 inwhich the XSAGD process is described. SPE 97647 teaches that since underSAGD it is impossible to move the injector and producer wells fartherapart vertically, to minimize steam breakthrough, this constraintnecessitates a lowering of oil production rates as the steam bank grows.However in the present SWAP invention taught herein, the communicationzone allows the distance between the injector locations (perforations)and producer locations (perforations) to be constantly changed as neededto meet the expanding steam bank zone dimensions and this implementationallows the new invention to maintain a more level rate of high oilproduction without any steam breakthrough and in many cases to increasesteam injection and consequently oil production as the operationsdevelop and the steam bank contacts a larger volume of reservoir rock.

Another aspect of the SAGD process inefficiency is the need to injectsteam in both injection and production wells for periods up to 415 daysto “pre-heat” the reservoir and create a communication zone between thetwo wellbores. In this subject invention as soon as a viable steam bankzone develops in a matter of days, hot oil begins to accumulate in thecommunication zone at the bottom of the steam bank and can be produced.Economically such a long delay can severely impact the economics of acapital project.

Another negative aspect of this SAGD process is the capital needs fordrilling and equipping two horizontal wells to implement the SAGDprocess. Furthermore, the SAGD process requires a vertical separationbetween these two horizontal wells and this property limits the SAGDprocess the relatively thick pay sections and cannot be used in thinreservoir sections. A yet further limitation of SAGD is the effects ofwater zones at the base of the oil formation on the SAGD process sincethe steam preferentially enters the water zone and bypasses the coldviscous oil zones. This limits the thermal and economic efficiency ofthe SAGD process. A yet further problem associated with the SAGD processis the presence of horizontal shale barriers in the oil formation. Thisshale layer between the horizontal wellbores is in effect a verticalbarrier and the SAGD process as designed and implemented is unable tooperate since the two horizontal wells are unable to communicate.

Additionally, to increase displacement efficiency in thermal recoveryoperations, there is a need to discriminate the quality of flowing fluidin the communication zone in a manner that allows the operator to openor shut off the production stream and allow the accumulated fluid tobehave as an effective hydraulic seal thus propagating the steamdisplacement in the steam bank. The subject invention offers a solutionto this need and provides the mechanism by which the solution can beimplemented using conventional equipment and procedures.

Shortcomings of prior art can be related a combination of effects. Theseinclude:

-   -   (1) the inability of the process to inject the hot fluid into a        cold highly viscous oil in a limited conductivity formation with        hydrocarbon viscosities in excess of 106 cp, with this viscosity        the liquid is essentially immobile at reservoir temperature.;    -   (2) the inability of the method to prevent bypass of injected        fluid directly from the injector source towards the producing        sink;    -   (3) the inability of the method to form and maintain a viable        communication zone from the steam zone or chamber to the        producing sink while simultaneously preventing bypass and early        breakthrough of steam;    -   (4) the inability of the process to utilize the very effective        gravity drainage flow component created by the low density of        the hot steam compared to the relatively high density condensed        water and hot oil;    -   (5) the inability of the process to heat the formation        effectively by physical contact between the steam and the rock        formation such that latent heat, the major source of steam heat        energy, can be transferred to the rock and hydrocarbons        efficiently;    -   (6) the requirement of long lead times of months to years of hot        fluid injection, before there is any measurable production        response of the displaced oil in the production wells;    -   (7) the inability of the existing technology to maintain and        sustain oil production rates when applied to large patterns of        several wells;    -   (8) the inability of the downhole devices to determine flowing        fluid characteristics other than temperature;    -   (9) the inability of the technology to discriminate between        flowing hot oil, hot water and steam in the flowing material;    -   (10) the inability of the devices to operate based on the        knowledge gained form these fluid characteristics;    -   (11) finally the use of overly complex equipment of questionable        operational effectiveness to implement the process in the field.

The above discussed and other problems and deficiencies of the prior artare overcome or improve upon by the heavy oil recovery system of thepresent invention by integrating a viable steam bank, an axial andconcentric communication zone, an active hydraulic seal, a sensibledownhole controller and an operative production system.

In contrast to the aforementioned prior art which try to measure fluidtemperatures, or pressures in the wellbore the present inventiondetermines the true nature of the fluid flowing, be it steam, hot oil,hot water or a combination of each fluid. This real time measurement isrequired since to adequately identify the steam flow a measure of steamquality must be made in real time to allow the controller to shut offthe oil production inflow from the steam bank

SUMMARY OF THE INVENTION

THIS NEW INVENTION provides an improvement in heavy oil recovery wherebythe operator injects a hot displacing fluid into a specially designedwell. An additional implementation is the development of an integraldownhole apparatus which behaves as a flow sensor, flow controller and aflow valve simultaneously. Operationally this device provides forflow-or-no-flow of produced fluids depending on the type of fluiddetected in the produced flow stream. If the flow is hot oil or waterthe flow device is opened, when steam is detected the valve is closed.In this application the term flow valve and flow device are usedinterchangeably for a physical element used to control fluid flow.

In this oil recovery method, the operator drills a well which is drilledfrom the surface down to the producing formation. There are severalembodiments of the well ranging from single vertical wellbores, tocombined vertical and horizontal wells and to the uniwell system whichhas two wellheads.

An object of this invention is to provide an improved process forrecovery of heavy oils and similar hydrocarbons from subterraneanformations. The invention uses a single well bore with an externalannular communication zone between the perforations. In this invention,the accumulation of hot oil and condensed water at the bottom of thesteam bank and in the vertical communication zone forms a securecontrollable hydraulic seal which prevents steam flow bypass away fromthe steam bank. An isolation packer vertically separates injection andproduction perforations.

In one embodiment, the external annular communication zone can beimplemented by an additional tubular string outside of the injection andproduction tubular string. The perforations for flow into and out of thewellbores are in the walls of the steel wellbore casings. In thisembodiment, the annular region is a void with infinite permeability. Inanother embodiment, an open-hole communication zone can be implemented.Depending on the rock formation and oil reservoir properties, thecommunication zone can range from a few inches to several feet indiameter.

The displacing fluid is forced into the upper perforations by a downholepacker and as steam accumulates heats up and displaces native oil thisoil and condensed water gravitate to the bottom of the steam bank andcollects in the communication annulus waiting to be produced when thedownhole controller opens the flow control valve. In this invention, theflow-no-flow operation permits oil and water production but shuts downwhen steam flow is detected in the flow stream.

An object of this invention is to provide an improved process forrecovery of heavy oils and other highly viscous hydrocarbons fromsubterranean formations by exploiting the advantages provided by gravitydrainage in the displacement process of heavy oils in porous formationsusing steam driven displacement processes. The use of a modified singlewell bore with coupled pairs of injector-producer perforations in closeproximity under positive and viable flow control has several engineeringbenefits including cost reduction, better fluid displacement and moreengineering control and accelerated economic recovery of the injectionand oil recovery process.

Another specific objective is to provide a means whereby the samewellbore perforations along the vertical section of the wellbore can beused sequentially for either injection or production as reservoir oildepletion occurs during steam field operations as required by theoperator.

Another specific objective is to use the movable packer between theinjection and production perforations, which forces the steam to exitthe wellbore and enter the oil zone at a preset location upstream of theproduction perforations.

Another specific objective is after the initial oil region is depleted,to unseat and move the movable packer between the injection andproduction perforations and the accessory downhole flow controllerapparatus a preset distance along the axis of the wellbore and reseatthem to allow the steam displacement process to continue throughout thereservoir in a new undepleted or virgin oil zone.

Another specific objective is to provide a concentric communicationchannel in the formation, which allows the heated oil to move from theupper steam zone to the production perforations in the lower productionzone rapidly and under gravity.

Another specific objective is to provide a means to considerably reducethe distance the heated oil has to move through the producing formationsfrom the steam injection point to be produced in the wellbore.

Another specific objective is to provide a means whereby oil productionbegins as early as possible during the injection process compared toexisting technologies like Steam Assisted Gravity Drainage (SAGD) andconventional Thermal Enhanced Oil Recovery (TEOR), where oil productiontakes place after a considerable length of steam injection ranging fromseveral weeks to several months and even years.

Another specific objective is to utilize and incorporate the lateralsteam gravity over-ride characteristics of the steam drive process toenhance the “backwards” flow of hot oil from the leading edge of thesteam displacement front to the hot oil accumulation zone and thecommunication zone in the invention.

Another specific objective is to utilize a set of staggered lateralmini-wellbores drilled into the oil formation to maximize the injectionefficiency of the steam so that a steam override effect is implementedsuch that a lateral physical flow gradient occurs in the oil zone with athin leading edge and a thicker trailing edge. The hot oil flows alongthis three-dimensional surface at the steam-oil interface.

Another specific objective is to allow the steam to replace oil and topressure up the steam bank at the top, which helps to displace lowviscosity, heated oil downwards along the interface of hot steam andcold reservoir oil via the communication annulus, to the producingperforations where there exists a localized pressure sink because oil isbeing removed during production.

Another specific objective is to use a downhole steam controllerapparatus to control the flow, no-flow of steam under specificoperational conditions.

Another specific objective is to use an operatively connected valveapparatus to shut off the flow of produced fluid in the wellbore whenthe steam sensor indicates that steam break-through has occurred andthat steam is flowing down the annular region from the steam bank to theproduction perforations.

Another specific objective is to monitor operations such that hot oil isproduced until continuous steam breakthrough is imminent then close thedownhole production valve.

Another specific objective is to control the downhole apparatus from thesurface.

Another specific objective is to utilize a scavenging displacing fluidto recuperate part of the residual hot oil in the heated oil formationby injecting this displacing fluid after the steam injection phase iscomplete.

This novel utilization proposed herein addresses the needs and teaches amethod and apparatus that is easily implemented, allows a larger portionof the reservoir to be exposed and allows more heavy oil recovery tooccur sooner.

Improvements have been made in enhancing the contact of the steam withthe native heavy oil by the introduction of horizontal well technology,which allows greater recovery than with the customary vertical wells.This current invention provides a further extension of the horizontaltechnology in which a novel well completion methodology is applied tothe recovery effort to allow wells of much larger lateral extent,potentially larger diameters and thereby more efficient recoverysystems.

By implementing the new method which is taught in this application bythis invention the oilfield operator can see improved performance, lowercosts, better oilfield management, and allow for efficient and orderlydevelopment of petroleum resources.

THIS NEW INVENTION provides an improvement in the recovery methods andoperations of other applications wherein the process of steam injectionwas controlled by a downhole apparatus forming a closed seal, whichprevents the production of fluids except under certain field conditionsand which on sensing the flow of steam shut off the production fluidflow completely.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention consists of the wellbore and associated componentsshown in the figures below:

FIG. 1 a Shows a schematic of the new downhole apparatus implemented ina uniwell™ system. It shows the steam bank, the injection and productionperforations, annular communication zone and the accumulated hot fluidsin the wellbore.

FIG. 1 b Shows a schematic of a lateral wellbore with the new downholeapparatus implemented in the lateral system. This implementation canconnect the lateral to a central production cavity.

FIG. 1 c Shows a vertical well embodiment with a central productioncavity below the wellbore. The steam downhole apparatus is implementedin the inner wellbore as shown.

FIG. 2 Shows the steam zone, the communication zone and the accumulatedhot fluids in the steam bank. Also shown is the downhole steamcontroller installed between the injection and production perforationsand also shown is the direction of flow of the steam and the hot oil asthey move down the communication zone into the wellbore. This figuredepicts a closed system in which the downhole apparatus is closed sothat no production occurs.

FIG. 3 Shows a schematic of the new downhole steam controller apparatusillustrating the various component locations. The steam sensor, thepacker seal, the valve controller, the shut off valve and the flow ofsteam and hot fluids around and through the apparatus.

FIG. 4 Shows a schematic of the new downhole apparatus implemented inthe wellbore. It also shows the fluid level at the bottom of the steambank and the flow direction for hot fluid entering the device.

FIG. 5 Shows a schematic of the new downhole apparatus illustrating thedevice in a closed no-flow condition. FIG. 6 Shows a schematic of thenew downhole apparatus illustrating the device in an open flow orproducing condition.

FIG. 7 a Shows a schematic of system operating with the new downholeapparatus in the closed position with the hot fluids accumulating toform a hydraulic seal at the bottom of the steam zone. Note the elevatedlevel of the steam-hot fluids interface.

FIG. 7 b Shows a schematic of system operating with the new downholeapparatus in the open position with the hot fluids draining, thuslowering the hydraulic seal level at the bottom of the steam zone andallowing the hot oil and water to enter the production cavity. Note thelower level of the steam hot fluids interface.

FIG. 8 Shows a flow chart of the operations during injection andproduction.

FIG. 9 a, 9 b, 9 c, 9 d Show 4 flow charts illustrating the sequence ofthe operations of the invention.

FIG. 10 Shows a graphic of the typical temperature viscosity behavior ofan oil sands oil.

FIG. 11 Shows a schematic of the development of the steam bank duringinjection in a system in which a series of horizontal shale barriersoccur in the oil formation.

FIG. 12 Shows a schematic of the scavenging phase in which water isinjected at the bottom of the formation as the displacing fluid inseparate wellbores after steam injection has depleted the oil formation.Also shown is the growth sequence overlay I, II, III, IV, V, VI of thesteam zone.

FIG. 13 Shows a schematic of the scavenging phase in which anon-condensing gas is injected at the top of the formation as thedisplacing fluid in separate wellbores after steam injection hasdepleted the oil formation. Also shown is the growth sequence overlay I,II, III, IV, V, VI of the steam zone.

FIG. 14 Shows a schematic of the wellbore system with a set of staggeredhorizontal mini-wellbores implemented to allow steam injection forming a“wedge” shaped profile.

List of Items No. Item  1 Wellbore  2 Downhole Steam Control Apparatus 3a Steel casing for wellbore  3b Steel casing or Liner for annularreamed zone  4 Steam bank in Oil Formation  5 Oil bearing formation  6aHot oil flowing  6b Non Flowing Hot Oil  7 Primary Steam Diverter packer 8 Annular Communication Zone  9a Injection perforations  9bPerforations in Cased Liner 10a Production perforations in innerwellbore 10b Production perforation in outer wellbore 11 Communicationelement 12 Injected Steam Flow down wellbore 13 Top of Formation 14aHigh Level - Hot Fluids - accumulating phase 14b Low Level - HotFluids - producing phase 15 Flow Device (Valve) in Downhole apparatus 16Slotted Liner for fluid inflow 17 Steam in Steam Bank and Annular region18 Flow sensor 19 Flow Valve Controller 20 Hot oil gravitating downsteam bank 21a Wellbore packer - internal 21b Wellbore packer - external22 Bottom of Formation 23 Steam and Hot oil interface 24 Steam Flowdirection 25 Surface Steam Generation System 26 WellHead 27 ProductionTubing 28 Production Pump 29 Production Cavity 30 Land surface 31Surface control devices 32 Wellbore for Scavenger water fluids 33Surface water injection facilities 34 Injection lines 35 Wellbore forScavenger ono-condensing gases 36 Surface apparatus for non-condensinggases 37 Injected Water 38 Injected non-condensing gas 39 Shale barriers40 Mini-wellbores

DESCRIPTION OF THE PREFERRED EMBODIMENT OF THE INVENTION

Referring now to the drawings, wherein like elements are numbered alike.Referring to FIG. 1 a, specialized wellbore 1 is drilled from thesurface down to and into the hydrocarbon bearing formation 5. Manydrilling rig configurations can be used, regular vertical type rigs orslant type rigs can be used to implement the drilling phase. In fieldapplications of this invention it is beneficial that the wellbores beoriented along the formation dip angle such that maximum effect ofgravity can be obtained in that the dip component adds to the gravitycomponent and increases the gravity segregation of the fluids because ofdensity differences. There are several embodiments of the wellboresystem as shown in FIGS. 1 a, 1 b, and 1 c. One of the many embodimentsincludes a uniwell system with two wellheads shown in FIG. 1 a, and asecond is a lateral wellbore which can be extended as shown in FIG. 1 bto intersect a central production cavity, and third a vertical wellborewith a production cavity shown in FIG. 1 c. These three options do notexhaust the available forms and anyone skilled in the art can implementsimilar or diverse systems for completing a similar wellbore. Asignificant novel improvement to the wellbore flow system isimplementation of an annular fluid communication zone 8 shown in FIGS. 1a, 1 b and 1 c. This is a zone of increased fluid conductivity which isconcentric to the wellbore 1 and forms an effective flow channel fromthe hot steam zone 4 to the lower producing zone of the wellbore system.This communication zone allows early gravity separation of the steam,hot oil and hot water. This early precipitation of the heavier anddenser fluid components of the reservoir frees up formation pore spaceallowing more steam 17 to be injected into the cold formation 5 andthereby heating the porous medium and increasing the steam zone 4 growthand attendant oil recovery. It is imperative that the steam has a freepore space to enter the formation without which, fluid displacement isimpossible at the typical operating fluid flow pressures. In practice,the annular zone is implemented in one embodiment by a steel casing 3 binstalled outside the inner wellbore 3 a. In the industry, this isgenerally done when the well is drilled. A steel liner or a steel screencan also be used to form the annular communication zone in anotherembodiment.

Operatively implemented in this wellbore and shown in FIG. 2, is a novelelement called a steam controller apparatus 2, which monitors andcontrols the flow of fluid into and through the wellbore 1 below theinjection packer system 7. This device is installed downstream of theinjection system adjacent to the production perforations 10 asillustrated in FIGS. 2 and 7 a and 7 b.

As shown in FIG. 3 the steam controller apparatus 2 comprises three mainsegments. An inflow section 16 in which the hot fluids enter the device.An upper steam sensor section 18 which senses the flow of gaseous steamthrough the device, a controller section 19, which monitors the steamflow and which controls the lower valve section 15 which opens andcloses the flow pathway to allow flow or shut off the flow of hotliquids as needed. Both elements have a complement of electronichardware and software as shown in FIG. 8. It is noted herein, that thedevice 2 has to detect steam flow which is more complex than justrecording or monitoring a fluid flow or a flow temperature. Theapparatus 2 is implemented in the wellbore 1 wherein the device isplaced between the upper injection perforations 9 a, 9 b and the lowerproduction perforations 10 a, 10 b. The apparatus 2 is anchored in amanner typical to the industry and easily accomplished by those skilledin the industry. In its initial placement in the wellbore, as shown inFIG. 5 and FIG. 7 a, the apparatus is set up in a closed state such thatno flow enters the production perforations 10. The no-flow situationallows the accumulation of hot fluids to occur in the communication zone8 and the bottom of the hot steam bank zone 4.

Referring to FIG. 2, the steam injection fluid 17, which is generated onthe surface in a steam generation system 25 is injected into thespecialized wellbore 1. The steam fluid 17 is injected down the wellboreand is directed into the cold viscous oil bearing formation 5 by theupper packer 7. The steam 17 enters the formation 5 through theperforations 9 a in the inner casing 3 a, strategically placed externalpackers 21 b prevent loss of steam down the annulus. This steam thenenters through the perforations 9 b of the outer casing 3 b. In theformation 5, it heats up the formation rock, the interstitial water andthe native oil, significantly lowering the oil viscosity as shown inFIG. 10 from hundreds of thousands of centipoises to tens of centipoisesand forming a steam bank or steam chamber 4. Because of the significantfluid density differences, the hot fluids, oil and water preferentiallyaccumulate at the bottom of this steam chamber 4 under gravity drainage.It should be noted that as the steam injected volumes 17 move into thefarther reaches of the reservoir 5, the steam profile appears as aninverted wedge, i.e. flat at the top and triangular on the bottom side,because the steam flows more rapidly at the top of the formation andthis override as reported by many researchers, creates a physical flowgradient at the lower surface of the steam bank 4. This steam bank 4 isvertically thinner at the front or leading edge and thicker at the nearwellbore 1 region. This phenomenon allows the hot oil to literally flowdownhill and backwards through the porous formation towards the bottomof the steam bank 4 where it collects and further into the communicationzone 8. It is also noted that this flow phenomenon occurs in3-dimensions since the steam bank 4 in all respects behaves like aninverted dome with the base being flattened and the walls of the domebeing the flow surface for hot oil and water. As shown in FIG. 2, a gascap, literally a steam cap 17 develops at the top of the productioninterval and an oil and water leg 14 a (high fluid level), 14 b (lowfluid level) develops at the bottom of the zone. This is a stablehydrodynamic situation and the accumulated hot fluids 14 a, 14 b behaveas a plug at the bottom of the hot zone and prevents steam from movingdown the communication zone 8. The interface 23 is a horizontal plane ofdensity differences between the gas zone and the hot oil and water zone.The accumulated hot fluids create a hydraulic plug 14 a, 14 b, whichprevents the steam from bypassing the cold formation and travelingdownwards to the production perforations. This plug behaves much like aP-trap in a plumbing system. The invention is designed such that the hotoil 6, condensed water and free steam are forced to flow down theannular conductive zone 8 from the injection zone to the productionzone. As shown in FIGS. 4, 7 a, 7 b, these hot fluids flow down thecommunication zone 8 from the injector zone and steam bank 4 to theproduction zone and production perforations 10 a, (in inner wellbore),10 b (in outer wellbore). This hydraulic plug is actively controlled bythe levels of oil production of the well and other operational actionsunder the direction and control of the well operator. Hot fluid entersperforations 10 b in the outer wellbore casing and then flows into theannular cavity 8 whence it enters through perforations 10 a into theinnermost wellbore 1 and contacts the input section 16 of the steamcontroller device 2. This new steam controller device 2 allows hot waterand hot oil to flow but a valve 15 shuts off flow when steam is detectedin the flow stream. Substantial flow of steam indicates that there is nomore oil to be produced from the formation.

In the field, the presence of horizontal shale barriers in the oil zoneas shown in FIG. 11 has always been a major obstacle to developers inthe prior art. The barriers 39 lower the efficiency of the displacementprocesses in view of the fact that they provide an almost impenetrablevertical barrier to steam and oil flow. This invention however,addresses and overcomes this major problem by the implementation of thevertical annular communication zone 8 at the near wellbore 1 region. Thepresence of this vertical communication zone 8 acts as a vertical reliefvalve for oil flow. In the displacement operations as shown hereinearlier, the hot oil 6 a, being displaced, will move counter-current,under gravitational flow, backwards along the shale barrier towards thewellbore because of the 3-dimensional characteristics of the steam bankin which the leading edge is always thinner than the trailing edge. Atthe near wellbore 1 region the communication zone allows vertical crossflow of the hot oil and hot condensed water towards the bottom of thewellbore and the collection and production systems. The hydraulic sealat the bottom of the steam bank has to be controlled to limit steambypassing in both layers.

This vertical cross-flow resolves the problem created by the shalebarriers. In the field, there may be a plurality of shale barriers shownin FIG. 11, and the same phenomenon will occur simultaneously in all thesteam displacement layers because the oil flow occurs along the surfaceof the steam bank interface with cold reservoir oil and the hot steam,and is not driven by pressure gradients but by the density differencesof the two fluid phases.

Referring to FIG. 14 in which a series of lateral or horizontalmini-wellbores 40 are drilled radially from the initial wellbore 1 toincrease steam injection efficiency. In this embodiment, themini-boreholes 40 they are drilled in a staggered pattern such that awedge-like cross-section of the steam bank is obtained when steam 17 isinjected. This cross-section wedge is thicker at the near wellboreregion and thinner at the leading or front edge of the steam 17. Thistype of profile provides a physical flow system in which the hot oil 20can flow backwards more readily to the bottom of the steam bank 4 andthe axial concentric communication zone 8. These mini-wellbores 40 canbe predrilled through out the oil formation 5 at specific verticaldepths prior to the steam injection process. In this way when theinjection system is moved axially down the main wellbore 1 thesepredrilled mini-wellbores 40 are already in place and available forsteam injection and can also aid in hot oil inflow to the communicationzone 8.

Referring to FIGS. 5, 6 which show that except under specificconditions, the steam control apparatus 2 prevents the flow of hotfluids 6 a through the production perforations 10 a, 10 b. When the hotfluid flow is allowed, the hot fluid comprising oil and condensed steamenters the wellbore 1 and flows down the well to the collection systemand the pumping mechanism 28 of the producing system. As the fluid flowsinto the steam controller apparatus 2, sensing components in the deviceshown in FIG. 8, detect the presence of steam. When steam is detected,the apparatus shuts off fluid flow as illustrated in FIG. 5 since thereis no more oil to be produced at the current time. However, continuoussteam injection still occurs in the wellbore in the upper injection zoneperforations 9 a and the accumulation of hot oil at the bottom of thesteam zone 4 continues. After a predetermined time as computed by thewell operator in which sufficient oil has accumulated, the apparatusreopens the production phase to allow the hot oil 6 a (flowing), 6 b(non-flowing) to be produced. Production of oil and water occurs whenthe downhole pump 28 is activated and the accumulated oil 14 a, 14 b inthe wellbore is produced in the customary manner used in the industry.If the downhole pressure is sufficient, it is possible to flow the oildirectly to the surface.

This steam controller apparatus 2 along with the wellbore packers 21 a,21 b are sequentially moved down the wellbore 1 and reseated in a newaxial location as the steam injection process continues until therecoverable oil in the formation 5 is depleted. In one rudimentaryembodiment of the invention, a downhole sensor 18 is not utilized butthe flow control apparatus 19 is turned on and off to open the flowvalve 15 at selected times for specific producing time intervals. This“dumb” approach using a “null” sensor can be used in situations wherethe sensors are unavailable. A further option of the “dumb” approach isto flow the wells in the producing cycle until steam is visible at thesurface 30 then to shut off the downhole valve 15 such that thehydraulic seal created by fluid 14 a, 14 b can start re-forming. Theseembodiments are wasteful of steam energy and reservoir productivityhowever, they can still function under the prevailing reservoirconditions and in operating conditions where the low cost of steamgeneration makes it economically attractive, examples are in some remoteforeign environments where environmental concerns on combustionprocesses for steam generation are not as stringently regulated. Analternative approach to using the “null” sensor uses historical dataanalysis to correlate statistically, injection and production times suchthat an intelligent estimate of the required production time beforesteam breakthrough occurs can be made. In this way, the “dumb” approachcan be more effective and lessen injected steam waste.

Power to the downhole apparatus 2 can be implemented by the power cable11 and information back and forth from the downhole apparatus to thesurface can be effected by either a wired or wireless telemetry system.Both systems are typical to the industry and can be done by anyonecompetent in the field. Optical fibers are a well-developedcommunications medium used in the telecommunications industry and havebeen progressively adopted for uses in sensors in the oil and gasindustry. One of the greatest benefits of these sensors is the hightemperature capability and reliability, which makes them well suited forsteam injection and other thermal recovery processes. These fiber opticsystems are intrinsically safe since they only transmit light and noelectrical flow occurs which completely removes the possibility of aspark to ignite the volatile hydrocarbons in the wellbore.

As shown in FIG. 3 and further illustrated in FIGS. 5, 6, 8, the device2 comprises the following elements. An inlet section 16 which isgenerally a slotted liner or a metal sieve to allow the hot fluids toenter the device. The fluid sensor 18 comprises a steam flow sensor forexample, a mass flow detector which is minimally capable of determiningin realtime the mass of flowing fluid as well as the temperature,pressure and quality of the flow stream. This sensor 18 has its ownlogic and computer capability to process the data and make it availableto other elements of the steam controller 2 and the surface devices 31.In addition operatively connected to the sensor system 18 is a flowdevice controller system 19. This flow device controller 19 has a fullcomplement of hardware circuitry, software and software logic, memoryand storage capabilities to process, store, transmit and implement theinstructions needed to control the operations of the flow valve 15directly or on command from the surface devices 31 as seen in FIG. 8.The flow valve or flow control device 15 is a system typical of the flowdevices in industry and are made in a variety of forms. These valvesystems 15 are well known in the industry and are actuated in a varietyof ways. Implementation of the combination of steam sensor, controllerand flow valve as a means of limiting steam flow through an axialcommunication zone below an operating steam bank provides a new means ofaccelerating production from a single well. This single well acceleratedproduction or abbreviatively called SWAP™ technology provides foraccelerated economics in the enhanced oil recovery industry.

Operationally the preferred embodiment of the invention is practiced asshown by the following: Referring to FIG. 9 a, step 110 illustrates thedrilling phase of the field application. In this phase, the operatorselects the type of well(s) that should be drilled. These types areshown in FIGS. 1 a, 1 b, 1 c, and FIG. 14 in the case of staggeredhorizontal or lateral mini-wellbores being implemented. After thewellbores 1 are drilled, in one embodiment, the communication zone 8 iscased and perforations 9 a, 9 b, 10 a, 10 b are made in the tubulargoods. As shown in step 111, packers 21 a and 21 b are prepared andseated as needed in the wellbores when the steam control device 2 isinstalled in the inner wellbore 1. At the same time, the operatorcomputes the steam injection times and rates. After these specifictimes, the operator can monitor and operations and trigger the downholesteam control device 2 to open up the flow valve 15 as dictated by theflow times. In step 112, steam is generated on the surface in steamgenerators 25, as shown in FIG. 1 In FIGS. 2 and 7 a, the steam isinjected down the wellbore 1, and meets the downhole packer 7 whichdiverts the steam flow 12 as seen in FIG. 4 thorough the injectionperforations 9 a and 9 b of the steel wellbore 3 a and the annularcasing 3 b. Flow down and out of the annular zone 8 is prevented bypackers 21 b.

In the operational case where no packers 21 b are used some steam can besacrificed to fill up the annular cavity with no great loss ofefficiency. The injected steam 17 begins to heat up the reservoirformation 5, it forms a steam zone or steam bank 4 in which hot oil andhot water accumulate with the steam. The high formation temperaturelowers the oil viscosity considerably as shown in FIG. 10 and this oilflow driven by the combined forces of gravity, formation dip angle andpressure in the steam bank 4, gravitates to the bottom of the zone toform a liquid saturated zone 14. This zone forms a fluid-steam contact23 in the formation similar to an oil/water contact in naturalreservoirs which is formed by fluid density differences. In thisinvention, the steam cap 4 is analogous to a gas cap and the fluid zone14 is analogous to an oil leg in typical hydrocarbon reservoirs. Asindicated in step 112 this layer of hot oil and water 14 a, 14 b forms ahydraulic seal at the bottom of the steam bank. This hydraulic seal 14is an integral part of the invention and its existence in the steam zone4 and the communication zone 8 prevents the flow of steam into thewellbore until this seal height is lowered or the fluid is removed byproduction.

The hot dense fluids, oil and water, enter the annular communicationzone through production perforations 10 b in the cased wellbore 3 b.Here they remain until the steam controller device 2 “allows” them toenter the production perforations 10 a and finally the inner wellbore 1.During the injection phase the steam bank grows and its growth andvolumetric extent can be easily calculated by many publicly availablecomputer simulation models. The operator as shown in step 113 monitorsthe injection process and is able to estimate the volume of oilaccumulating at the bottom of the zone 4 in the oil leg 14 a, 14 b. Atthe pre-determined time the downhole steam controller 2 is triggered bythe control device 31, the flow control valve 15 is opened and hotfluids begin to enter the inflow section 16 of the device 2 and flowpast the steam sensor 18. The steam flow sensor measures the fluidcharacteristics as shown in steps 102, 103, 104, 105, 106, 107 of FIG.8. As the flow continues, the level of the fluid interface 23 islowered, the fluid leg drops from a high volume at 14 a to a lesservolume at 14 b as shown in FIG. 7 b. This fluid lowering occurs in thesteam zone 4 and in the communication zone 8. The produced fluids oiland water collect in the inner wellbore, are transported under gravity,and flow pressure to the production zone of the respective well systemsused. These can be either into the production cavity 29 of FIG. 1 c orthe lateral wellbore of FIG. 1 a, or the central production cavitydescribed for FIG. 1 b. In all cases, the production mechanism 28 isused to lift the oil to the surface if there is insufficient pressurefrom the injected fluids to lift the fluid to the surface.

As oil production continues through the steam controller device 2, theflow characteristics are monitored constantly by device element 18 andthe information is processed locally or remotely at the surface. Whenthe sensor detects the flow of live steam 17 entering the wellbore 1,the valve controller device 19 triggers the valve 15 to close and nomore fluid flow 6 a, 6 b is allowed to enter the wellbore 1. Thisoperation creates a shut-off situation and hot fluid 14 a, 14 b beginsto re-accumulate in the communication zone 8 and the bottom of the steamzone 4. This re-accumulation creates a new hydraulic seal which preventsthe steam from bypassing the cold oil formation and directs it to enterthe formation 5 where it remains at the top of the steam zone 4. Steaminjection continues at all times during the production phase.

As indicated in step 114, the operator has to make a decision when theoil in the steamed zone 4 is depleted. If an analysis of the cumulativeoil volume produced indicates that the reservoir formations 5 areeconomically depleted, then the heavy oil recovery operations areterminated. If however, there is still economically recoverable oil inthe reservoir the injection site for steam injection through theperforations and the steam controller device must be moved axially downthe length of the wellbore to a new location to exploit additional oilreserves. This translocation process is shown in step 115. In this step115, steam injection is temporarily halted, the packers 21 a, 21 b areunseated, the steam controller 2 is unseated and both systems are moveda calculated distance down the wellbore 1 to be reseated opposite a newset of injection 9—production 10 pairs of perforations.

After this re-location, all systems are re-established and steaminjection continues.

This process of injection, production, decision analysis and relocationcontinues until the reservoir is fully depleted as shown in step 116.Steam injection and production are then terminated and the displacementscavenging operations are initiated as shown in step 117 of FIG. 9 d.This process is an “oil salvage” process in which displacing fluids areinjected into the hot formation 5 after steam displacement is complete.This is recuperative process well known in the industry in whichadditional oil can be recovered by flowing these displaced fluidsthrough a hot reservoir with reduced viscosity oil. The scavengingdisplacement process is helped by the fact that the heated reservoirrock has a higher porosity, higher permeability and the residual oil hasa lowered viscosity, all of these factors are complimentary in theireffects in promoting additional recovery of in-situ oil. Field testshave shown that as much as 22% of the total oil recovered can beachieved after the scavenging process is initiated. In implementing thescavenging phase, the injected displacing fluids are injected in aplurality wellbores. These wellbores are either:

-   -   (a) newly drilled horizontal and vertical injector wellbores; or    -   (b) existing wellbores formerly used for steam injection.

Referring to FIG. 12 treated water 37 from a surface supply source 33 isinjected down an injector well 32 and enters the formation at the bottomof the depleted steam bank 4. In one embodiment, these injector wells 32can be vertical wellbores or in other embodiments, they can besubstantially horizontal wellbores. This water 37 displaces the oiltowards the wellbore 1 which has all its perforations 9 a, 9 b, 10 a, 10b open to allow oil flow into the wellbore driven by the water pressureand production of displaced oil and hot water occurs and is pumped tothe surface.

Referring to FIG. 13 non-condensing gas or flue gas from a surfacesupply source 36. The supply source can be the treated exhaust of thesteam generation equipment 25. This flue gas 38 is injected down aninjector well 33 and enters the formation 5 at the top of the depletedsteam bank 4. In one embodiment, these injector wells 33 can be verticalwellbores or in other embodiments, they can be substantially horizontalwellbores. This gas 38 displaces the oil towards the wellbore 1 whichhas all its perforations 9 a, 9 b, 10 a, 10 b open to allow oil flowinto the wellbore driven by the gas pressure and production of displacedoil and gas occurs and the oil is pumped to the surface. The gas can beproduced up the casing annulus of the wellbore. Being less dense theinjected flue gas remains at the top of the steam bank while the denserwater gravitates to the bottom of the steam bank 4.

In one embodiment, both water injection and flue gas injection can occursimultaneously or sequentially. After gas and water breakthrough hasoccurred, injection is continued to the economic limit of the projectsand then terminated as shown in item 118 of FIG. 9 d.

REFERENCES

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1. A method for recovering hydrocarbons from a subterranean formationcontaining viscous oil or other heavy hydrocarbons, the methodcomprising the steps of: (a) drilling at least one wellbore down to andpenetrating the subterranean formation; (b) providing a wellhead at theentrance or proximal end of the wellbore; (c) providing at least one setof upper injection perforations and lower production perforations in thewellbores at pre-selected intervals; (d) installing at least onedownhole wellbore packer between upper and lower perforations; (e)forming a discrete annular zone for increased axial fluid communicationnear the said wellbore in the said formation so that heated lowviscosity oil and hot water produced from condensed displacing fluid canflow downwards to the lower production perforations; (f) implementing anactive hydraulic seal in said annular communication zone; (g) installinga downhole flow control apparatus; (h) heating the said formation byinjecting a displacing fluid into the formation; (i) communicating withthe downhole flow control apparatus from the surface; (j) computing theprescribed times for triggering the downhole flow control apparatus; (k)lifting the produced oil and displaced fluids to the surface; (l)producing the wellbore fluids at less than a critical rate so that theeffects of the displacing fluid coning are substantially eliminated; (m)scavenging the formation residual hot oil by injecting a displacingscavenger fluid.
 2. The method of claim 1, wherein the said formation isheated by injecting steam through wellbore perforations as a displacingfluid.
 3. The method of claim 2, wherein the injected steam heats thewellbore and surrounding formation for sufficient time and to acalculated temperature.
 4. The method of claim 1, wherein the step offorming said annular zone comprises: installing a steel pipe selectedfrom the group consisting of steel casings, steel liners, self-expandingor fixed sand screens
 5. The method of claim 2, wherein the saidinjected steam forms a steam chamber or steam bank.
 6. The method ofclaim 1, wherein the hydraulic seal in the communication zone forms as ano-flow barrier for vertical steam flow.
 7. The method of claim 1,further comprising the step of: installing a fluid recovery system tolift the produced oil and displaced fluids to the surface, wherein theproduced oil and displaced fluids are lifted to the surface by using thesaid fluid recovery system.
 8. The method of claim 7, wherein the saidfluid recovery system comprises a plurality of devices including: (a)displacement pumps, (b) gas lift devices, (c) cavity pumps.
 9. Themethod of claim 1, wherein the wellbore has a downward, lateral and anupward section terminating in a new surface wellhead forming a uniwell.10. The method of claim 1, wherein the wellbore has a downward section,a lateral section and terminating in a central production cavity. 11.The method of claim 1, wherein the wellbore has a downward section andan enlarged axial central production cavity.
 12. The method of claim 1,further comprising the step of cementing a steel casing in the wellborein the said formation.
 13. The method of claim 1, wherein a plurality oflateral and horizontal injection mini-wellbores are implemented in astaggered manner operatively connected to the central wellbore.
 14. Themethod of claim 9, wherein the wellhead at the proximal end of thewellbore is an injection wellhead and the distal end of the wellbore isa production wellhead.
 15. The method of claim 1, wherein theperforations in the wellbore are positioned as paired groups orcouplets.
 16. The method of claim 15, wherein the proximal perforationsin the pair group form an injector set of perforations.
 17. The methodof claim 15, wherein the next or distal set of perforations in the pairgroup form a producer set of perforations.
 18. The method of claim 1,wherein the downhole packer in the wellbore is placed between theinjector and producer pair of perforations separating the injection andproduction zones.
 19. The method of claim 1, wherein the downhole packerforces the injection fluid to be to exit the wellbore and be injectedinto the hydrocarbon bearing formation through the upper injectionperforations.
 20. The method of claim 1, wherein the downhole packer isretractable and has either a solid or an inflatable element.
 21. Themethod of claim 1, wherein the injected displacing fluid is steam. 22.The method of claim 1, wherein the injected displacing fluid forms asteam bank or chamber in the hydrocarbon reservoir.
 23. The method ofclaim 1, wherein the annular communication zone is concentric to thewellbore.
 24. The method of claim 1 wherein the diameter of the annularcommunication zone ranges from at least 8 inches to several feet. 25.The method of claim 1, wherein after each steam displacing zone isdepleted of hydrocarbons the downhole packers, and the downhole flowcontroller apparatus, are unseated and moved axially along the wellboreand re-seated adjacent to new hydrocarbon-rich zones in the formation toimplement the said recovery method.
 26. A downhole flow controlapparatus comprising: (a) a fluid flow sensor; (b) a flow valve or flowcontrol device for restricting fluid flow; (c) a flow device controllerfor controlling the flow control device; (d) means for communicating;(e) a wellbore packer; (f) means for delivering operational power to theapparatus; and (g) a surface control device.
 27. The apparatus of claim26, wherein the fluid flow sensor is upstream of the flow valve.
 28. Theapparatus of claim 26, wherein the fluid flow sensor is downstream ofthe flow valve.
 29. The apparatus of claim 26, wherein the fluid flowsensor measures a plurality of material flow characteristics includingpressure, temperature, mass rate and quality of the flow stream.
 30. Theapparatus of claim 26, wherein said fluid flow sensor is selected fromthe group consisting of electronic, optical, mechanical and electricalsensors.
 31. The apparatus of claim 26 wherein said fluid flow sensorcommunicates with a downhole processor, said downhole processor beingadapted to process the raw flow data sensed by said steam flow sensor toderive processed data, said processed data being selectively transmittedto the surface.
 32. The apparatus of claim 26 wherein said fluid flowsensor communicates with a downhole processor, said downhole processorbeing adapted to process the raw flow data sensed by said steam flowsensor to derive processed data, said processed data being selectivelyutilized to directly control the flow control device in the steamapparatus.
 33. The apparatus of claim 26 further comprising a controlcircuit for controlling the operation of the flow control apparatus. 34.The apparatus of claim 33 wherein the control circuit is placed at aremote place from the device.
 35. The apparatus of claim 33 wherein thecontrol circuit communicates with the flow control device via aconductor.
 36. The apparatus of claim 33 wherein the control circuitcommunicates with the flow control device via telemetry.
 37. Theapparatus of claim 33 wherein the control circuit includes a memorysystem capable of storing instructions for operating the flow controldevice independently of the surface.
 38. The apparatus of claim 26,wherein the fluid flow sensor activates the flow control device.
 39. Theapparatus of claim 26, wherein the flow control device controls the flowof fluid through the wellbore.
 40. The apparatus of claim 26, whereinthe fluid flow through the wellbore is greater than zero when the flowdevice is open.
 41. The apparatus of claim 26, wherein the fluid flowthrough the wellbore is zero when the flow valve is closed.
 42. Theapparatus of claim 26, wherein the fluid flow sensor detects the flow ofhot oil.
 43. The apparatus of claim 26, wherein the fluid flow sensordetects the flow of hot water.
 44. The apparatus of claim 26, whereinthe fluid flow sensor detects the flow of steam.
 45. The apparatus ofclaim 26, wherein the fluid flow sensor detects the combined flow ofsteam, hot oil and condensed water.
 46. The apparatus of claim 26,wherein the fluid flow sensor detects the mass flow rate of the flowstream.
 47. The apparatus of claim 26, wherein the fluid flow sensordetects the temperature of the flow stream.
 48. The apparatus of claim26, wherein the fluid flow sensor detects the mass flow rate andtemperature of the flow stream simultaneously.
 49. The apparatus ofclaim 26, wherein the fluid flow sensor triggers the flow devicecontroller when the flow sensor detects the flow of steam.
 50. Theapparatus of claim 26, wherein the flow device controller closes thefluid flow device when the flow sensor detects the flow of steam. 51.The apparatus of claim 26, wherein the flow device controllercommunicates with the surface control device.
 52. The apparatus of claim26, wherein the flow device controller receives a signal from thesurface control device after a prescribed time.
 53. The apparatus ofclaim 26, wherein the signal from the surface to the flow devicecontroller triggers the controller to open the flow control device. 54.The apparatus of claim 26, wherein said flow device controller isselected from the group consisting of electrical, electronic, optical,mechanical, hydraulic, pneumatic and electrical controllers.
 55. Theapparatus of claim 26 wherein the communication with the surface is by awired connection.
 56. The apparatus of claim 26 wherein thecommunication with the surface is a wireless communication.
 57. Theapparatus of claim 26 wherein the communication with the surface isthrough the steel wellbore using a plurality of electromagnetictransmissions.
 58. The apparatus of claim 57 wherein the communicationwith the surface is analyzed using Digital Signal Processingtechnologies.
 59. The apparatus of claim 26 wherein the device operatesin a “null” sensor mode comprising; (a) receiving a control signal atpre-selected timed intervals; (b) opening the production valve for oilflow; (c) keeping the production valve open for a fixed time period; (d)shutting the downhole valve after a timed interval.
 60. The apparatus ofclaim 59 wherein the control signal can be sent remotely from thesurface or can be generated by an embedded downhole timing mechanism.61. The method of claim 1 wherein the injected displacing scavengerfluid is water.
 62. The method of claim 1 wherein the injecteddisplacing scavenger fluid is non-condensible gas such as flue gas. 63.The method of claim 61, wherein the injected displacing scavenger wateris injected in a plurality of wellbores comprising: (a) newly drilledhorizontal and vertical injector wellbores; (b) existing wellboresformerly used for steam injection.
 64. The method of claim 61, whereinthe injected displacing scavenger non-condensible gas is injected in aplurality of wellbores comprising: (a) newly drilled horizontal andvertical injector wellbores; (b) existing wellbores formerly used forsteam injection.
 65. The method of claim 63, wherein the injecteddisplacing scavenger water is injected at the bottom of the steam bankin the oil formation.
 66. The method of claim 64, wherein the injecteddisplacing scavenger non-condensible gas is injected at the top of thesteam bank in the oil formation.
 67. The method of claim 1, wherein theinjected displacing scavenger fluids are injected simultaneously. 68.The method of claim 1, wherein the injected displacing scavenger fluidsare injected separately.
 69. The method of claim 1, wherein the criticalproduction rate is less than 5,000 barrels of fluid per day.
 70. Themethod of claim 1 wherein the prescribed time for triggering thedownhole flow controller is determined by the use of a computer model.71. The method of claim 1, wherein the step of forming said annular zonecomprises implementing an open hole completion without a steel casing.